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01 March 2003

Cutting out the noise

By Murry Magness

Bay Gas Storage Ltd. stores and dispenses natural gas from a salt dome cavern capable of storing 4 billion standard cubic feet of gas. The gas transports to the facility through a 20-inch (in) pipeline operation at 600-900 pounds per square inch, gauge (psig). The gas is then compressed and injected into a man-made storage cavern 4,000 feet below the surface.

Drilling a well into the natural salt dome was the first step in creating the cavern back in 1994. Water then circulated throughout the cavern to dissolve the salt.

After completion of the leaching of the cavern, the remaining salt-saturated water exited the cavern after officials injected natural gas at a pressure of 2,700 psig. Olin Corp. used the saturated brine in its manufacture of chlorine and caustic soda.

In the spring of 2001, Bay Gas brought in a new 20-in pipeline to primarily supply gas to several heavy industrial users, the largest being Alabama Power's Barry Combined Cycle power generation facility. The design of the pipeline allowed it to operate at a nominal pressure of 900 psig with a projected maximum flow rate of 600 million standard cubic feet per day (scfd).

Designed as dual stage compressors to inject gas into the salt dome, the company modified the compressors to operate in single stage mode. This allowed Bay Gas to accept gas from the original 20-in pipeline at 600-800 psig and compress it to 900 psig. This recompressed gas could then transfer to the new 20-in pipeline for use by customers.

With both compressors operating in single stage mode, the total throughput to the new pipeline was 100 million scfd (50 million scfm/compressor). Withdrawing gas from storage and adding it to the recompressed gas flow could then make up any additional gas capacity requirements.

Adding on

A new gas line came online to supply gas to heavy industrial users. The diagram shows the design of the new 20-inch pipeline.

New flowmeter installation

Flow measurement in and out of the Bay Gas station is critical because the company charges customers based on the gas stored at or removed from the station. Custody transfer accuracy is required for all gas entering or leaving the station. With the new 20-in pipeline, a new flow measurement station had to meet the station demands. Current flow measurement into and out of the plant occurs on a 12-in turbine flowmeter with a maximum capacity of 260 million scfd.

In selecting a new flowmeter to install at the new meter station, several features went into consideration.

First of all was the necessity for a wide range of flow measurement. The new meter had to measure flows as low as 10 million scfd and as high as 600 million scfd. The meter needed to meet certification to the AGA9 standards. The meter also needed to be able to measure flow both into and out of the plant. The initial installation called for gas to move from the station into the new 20-in pipeline, but future needs projected the possibility of sending gas into the station from this pipeline.

The existing 12-in turbine meter station has the capability of measuring gas flow both into and out of the station. However, getting to the point of allowing gas to flow both ways ended up being a very expensive proposition.

The maximum flow through this meter is 260 million scfd. To obtain additional flow capacity through this meter station, officials placed a 12-in orifice meter run with a senior orifice fitting in parallel to the turbine meter. This move allowed total flow measurements in the 500 million scfd range.

Ultrasonic flowmeters use the properties of acoustics to determine the velocity of the fluid passing through the meter. In gas measurement, the measuring elements consist of one or more pairs of ultrasonic transducers located along the pipe wall of the meter.

Unlike liquid ultrasonic meters, whose transducers do not necessarily come into contact with the flowing fluid, the transducer pairs in gas service actually come into contact with the gas. In gas measurement meters, the geometric relationship between the transducer pairs must be very precise.

Although most gas ultrasonic meters use multiple reflection path transducer configuration arrangements, a point-to-point sensor arrangement most easily illustrates the principle of operation and the math associated with it. The equations still apply with single or double path sensor arrangements.

The transducer arrangement yields the following equations:

acoustic path length

(1)

transit time with flow

(2)

transit time against flow

(3)

where L is the length of the sound path, c is the speed of sound, and v is the velocity of the flowing fluid.

(4)

Combining equations 1, 2, and 3 can calculate the flow velocity, v. Equation 4 allows the direction of flow to be determined by the sign of T. Positive values would indicate flow from left to right, and negative values would indicate flow from right to left. This simple example assumes a constant flow velocity all the way across the meter. This is normally not the case.

To compensate for a changing velocity profile and for swirl patterns that can develop in flowing gas, meter manufacturers use three or more sets of transducers and reflect the transducer signals off the pipe wall once or more. Microprocessor electronics can then analyze these signals and apply much more advanced flow equations to precisely calculate the flow velocity.

Ultrasonic noise abatement

When placing an ultrasonic flowmeter into operation, you must consider the sources of ultrasonic noise in the piping system. In any application such as salt dome storage of natural gas, at least one major source of noise will exist. The gas storage dome operates at between 2,100 and 3,200 psig at the well head. The dehydration system operates at 1,400 psig. The pipeline that accepts the gas is normally operating at 600-900 psig.

The gas comes from the well through a "first cut" regulator station consisting of three control valves in parallel. The valves are 3, 6, and 8 in, and you may use them individually or together, as determined by the flow capacity required. These valves are all equipped with noise abatement trim. With pressure drops as high as 1,800 psi across these valves, sonic velocity almost always occurs, and the noise from the valves without noise abatement trim would be in excess of Occupational Safety and Health Administration limits.

Rigging for quiet

The top graphic shows the initial design, and the bottom one shows the added modifications for noise attenuation. Because the designers addressed this before installing the meter, they minimized any additional expense.

Noise abatement trim in valves does not actually eliminate the noise created by sonic flow but rather shifts the frequency of the noise from the range of the human ear to a higher frequency that cannot be heard. This works well for the noise hazard but can cause problems when an ultrasonic flowmeter is in the piping system. The higher-frequency noise can interfere with the operation of the meter because the transducer frequency of the meter and the noise frequency of the valves can overlap.

In the case of the system at Bay Gas, the first cut regulators were upstream of the dehydration units, and all of the first cut noise dampened out when it passed through the dehydration towers. Due to this dampening, the first cut noise was not a problem.

The "second cut" regulators reduced the pressure from the in-plant level of 1,400 psig to the pipeline delivery pressure of 800 psig. This 600-psi drop was also a source of ultrasonic noise located close to the meter. Piping designers took steps to add noise attenuators at points in the pipe between the second cut regulators and the ultrasonic meter to eliminate the noise as much as possible.

The initial design called for piping elbows. The flowmeter vendor did an analysis of the piping system based on the predicted ultrasonic noise generated by the second cut regulators. The vendor recommended replacing the elbows with capped Tees. The projection was that with the other elbows and line size changes in the piping, they would achieve a dampening of 40 decibels.

The capped Tees caused the sound wave passing down the flow stream to reflect back on itself, canceling out some of the noise. In fact, after the installation was complete, sound measurements made at the meter were unable to detect any ultrasonic interference from the second cut regulators.

Checkout and start-up ended up being a nonevent. We just plugged it in and turned it on. The meter right out of the box matched the existing custody transfer certified 12-in turbine meter to the second value after the decimal point. This was probably the easiest start-up we have ever had. The vendor's start-up engineer said ours was typical of most installations.

At the end of the day, ultrasonic flow measurement of natural gas is an accurate, cost-effective application of this technology. By taking care to ensure that noise sources are far away from the meter or by using some simple piping additions such as Tees instead of Ells, we had a successful installation. The wide flow range and the bidirectional features of the meter enhance the installation. FT

Behind the byline

Murry Magness, P.E., is a senior engineer at BE&K Engineering in Mobile, Ala. His e-mail is magnessm@bek.com.